Dual pump reverse flow through phase behavior measurements with a formation tester

ABSTRACT

A downhole PVT tool for performing in-situ formation fluid phase behavior characterizations in a wellbore using pressure, volume, and temperature (PVT) measurements of the formation fluid while continuing to pump the formation fluids. The disclosed downhole PVT tool includes an intake mandrel and utilizes two individual pumps to split the formation fluid to perform PVT measurements during the fluid pump out. The downhole PVT tool, two-pump configuration permits a first pump to be used to pump formation fluid along a first flowpath and a second pump to be used to pump formation fluid along a second flowpath, with one or more sensors deployed along one of the flowpaths to perform fluid and/or gas phase behavior measurements to determine one or more properties of the formation fluid in-situ. The first pump may be utilized in the phase behavior analysis while the second pump simultaneously continues flow-through pumping of the formation fluid.

TECHNICAL FIELD

The disclosure relates, in general, to wellbore fluid measurements, andmore specifically to tools and methods for performing downhole phasebehavior measurements of formation fluids in a wellbore.

BACKGROUND

During the drilling and completion of oil and gas wells, it may benecessary to engage in ancillary operations, such as evaluating theproduction capabilities of formations intersected by the wellbore. Forexample, after a well or well interval has been drilled, zones ofinterest are often tested to determine various formation properties orformation fluid characteristics, or to gather fluid samples. Examples offormation fluid information which can be obtained include formationfluid identification, fluid type, fluid quality, formation permeability,formation temperature, formation pressure, bubblepoint and formationpressure gradient. These tests are performed in order to determinewhether commercial exploitation of the intersected formations is viableand how to optimize production. The acquisition of accurate data fromthe wellbore is important to the optimization of hydrocarbon wells. Thiswellbore data can be used to determine the location and quality ofhydrocarbon reserves, whether the reserves can be produced through thewellbore, and for well control during drilling operations.

One particular area of interest is the study of pressure, volume, andtemperature (PVT) changes on formation fluid, and specifically howchanges in PVT impact phase behavior of the formation fluid. In suchcase, it is sometimes desirable to obtain a sample of formation fluidthat may be substantially free of contaminants such as mud filtrate orother formation debris entrained in the formation fluid sample orotherwise to understand the degree of contaminants and their impact onPVT and phase behavior. In the prior art, downhole PVT tools for suchanalysis include a main flowline or flowpath for the formation fluid anda bypass flowline or flowpath. A single pump directs formation fluidalong the main flowline and a valve downstream of the pump may be usedto close off the main flowline and direct the pumped formation fluidinto the bypass flowline where the formation fluid is isolated fortesting. Upon isolation of this formation fluid sample, the bypassflowline is closed off and formation fluid flow can be resumed along themain flowline. One drawback to such prior art downhole PVT tools is thatthe altered flowpath may negatively impact the formation fluid samplefor phase change evaluation purposes. For example, the turbulence froman altered flowpath may result in a fluid sample with more formationdebris entrained in the fluid and may also alter the phasecharacteristics of the formation fluid sample. Another drawback is thatisolation activities limit continued flow-through activities along themain flowline.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present disclosure and theadvantages thereof, reference is now made to the following briefdescription, taken in connection with the accompanying drawings anddetailed description:

FIG. 1 is a schematic illustration of an offshore oil and gas platformoperably coupled to a subsurface wellbore, according to one or moreembodiments of the present disclosure.

FIG. 2 is a cross-sectional view of a pressure, volume, and temperature(PVT) tool for downhole testing within a wellbore illustrated in FIG. 1, according to one or more embodiments of the present disclosure.

FIG. 3 is a cross-sectional view of another embodiment of a downhole PVTtool of FIG. 1 , according to one or more embodiments of the presentdisclosure.

FIG. 4 is a flow diagram of a method for performing in-situ wellborephase behavior analysis of formation fluid.

DETAILED DESCRIPTION

The downhole PVT tools and methods disclosed herein relate to pressure,volume, and temperature (PVT) measurements of formation fluid, andspecifically relate to the study of phase behavior of the formationfluid at various PVT measurements while pumping the fluid in asubsurface wellbore. In accordance with disclosed embodiments, thedownhole PVT tool permits fluid phase behavior analysis using PVTmeasurements to be performed while continuing to pump formation fluidthrough the downhole PVT tool along a main flow line or flowpath withoutthe need to suspend flow along the main flow line. In some embodiments,this can result in a formation fluid sample that is less contaminatedthan samples obtained by prior art downhole PVT tools. Regardless, thiscan also allow continued flow-through of formation fluid along the mainflowline even as phase behavior of the formation fluid is beinganalyzed. The downhole PVT tools and methods disclosed herein utilizetwo individual pumps to isolate a formation fluid sample. A first pumpis utilized to direct formation fluid along a first flowpath while asecond pump is used to independently direct formation fluid along asecond flowpath. In some embodiments, the first pump may draw formationfluid from the second flowpath as the formation fluid continues to flowalong the second flowpath. The formation fluid drawn by the first pumpfrom the second flowpath is directed to a first flowpath for isolationand analysis. The first pump can be utilized to pressurize the isolatedformation fluid sample along the first flowpath while formation fluidcontinues to flow uninterrupted along the second flowpath. Once theformation fluid sample is isolated along the first flowpath, various PVTmeasurements can be obtained, and as stated, the formation fluid samplein the first flowpath may be pressurized utilizing the first pump.Thereafter, pressure on the formation fluid sample may be bled off byallowing the isolated formation fluid sample to flow to the wellboreannulus or merge back with the second flowpath. In some embodiments, thefirst pump may be reversed and operated to pump the formation fluidsample into the wellbore annulus or into the second flowpath. In someembodiments, a 4-way high pressure valve may be utilized to accomplishthe pump reversal activities that are needed for performing themeasurements, although other implementation and/or methods of pumpreversals can also be employed. In some embodiments, a metered pump canbe used, for example, for fine control during PVT measurements,including for example, during depressurization.

As introduced above, the disclosed downhole PVT tools and methods aredesigned to perform in-situ phase behavior characterization based on PVTmeasurements, including for example, density measurements as a functionof pressure in the downhole environment. Example fluidiccharacterization approaches may include, but are not limited to, forexample probing gas to liquid volume measurements as a function ofpressure. In various implementations of the downhole PVT tools, constantcomposition expansion experiments can be performed for phase behavioranalysis, for example, for performing fluid fraction, compressibility,viscosity, and gas-oil-ratio (GOR) measurement. In addition, thedownhole PVT tools and methods can be configured to perform gas phaseonly measurements to measure, for example, hydrogen sulfide (H₂S) in asubsurface wellbore.

Disclosed herein are embodiments of a downhole PVT tool and methods forperforming in-situ phase behavior measurements in a wellbore. In one ormore embodiments, the downhole PVT tool has a two pump configuration,where a first pump is used to pump fluid along a first flowpath and asecond pump is used pump fluid along a second flowpath, with one or moresensors deployed along one of the flowpaths to perform fluid and/or gasphase behavior measurements to determine one or more properties of theformation fluid in-situ.

Referring to FIG. 1 , in an embodiment, an offshore oil and gas rig isschematically illustrated and generally referred to by the referencenumeral 10. In an embodiment, the offshore oil and gas rig 10 includes asemi-submersible platform 15 that is positioned over a submerged oil andgas formation 16 located below a sea floor 20. A subsea conduit 25extends from a deck 30 of the platform 15 to a subsea wellheadinstallation 35. One or more pressure control devices 40, such as, forexample, blowout preventers (BOPs), and/or other equipment associatedwith drilling or producing a wellbore may be provided at the subseawellhead installation 35 or elsewhere in the system. The platform 15 mayalso include a hoisting apparatus 50, a derrick 55, a travel block 60, ahook 65, and a swivel 70, which components are together operable forraising and lowering a conveyance string 75. The conveyance string 75may be, include, or be part of, for example, a casing, a drill string, acompletion string, a work string, a pipe joint, coiled tubing,production tubing, other types of pipe or tubing strings, and/or othertypes of conveyance strings, such as wireline, slickline, and/or thelike. The platform 15 may also include a kelly, a rotary table, a topdrive unit, and/or other equipment associated with the rotation and/ortranslation of the conveyance string 75. A wellbore 80 extends from anupper end or surface end 80 a adjacent the subsea wellhead installation35, through the various earth strata, including the submerged oil andgas formation 16, to a lower or terminal end 80 b. At least a portion ofthe wellbore 80 may include a casing 85 cemented therein by cement 87.The conveyance string 75 is, includes, or is operably coupled to adownhole PVT tool 110 so as to position the downhole PVT tool 110 withinwellbore 80 at a subterranean location. Although downhole PVT tool 110is illustrated in FIG. 1 in a horizontal wellbore 80, wellbore 80, andits orientation, are for illustrative purposed only and downhole PVTtool 110 can function equally well in vertical wellbores of otherdeviated wellbores.

Referring to FIG. 2 , with continuing reference to FIG. 1 , in anembodiment, the downhole PVT tool 110 is shown as downhole PVT tool 200.Downhole PVT tool 200 is operable to perform phase behavior measurementsin-situ on formation fluids. In one or more embodiments, the downholePVT tool 200 has a first tool end 210, which can be referred to as theupper end, and a second tool end 220, which can be referred to as thelower end. It will be appreciated that in one or more embodiments,downhole PVT tool 200 is generally positioned within a wellbore 80 sothat first tool end 210 extends towards the surface end 80 a of wellbore80, while second tool end 220 extends towards the terminal end 80 b ofwellbore 80. Moreover, whether wellbore 80 is substantially vertical ordeviated, in one or more embodiments, first tool end 210 will generallybe positioned above, or otherwise have a higher elevation than, secondtool end 220 such that gas entrained within formation fluid capturedwithin downhole PVT tool 200 will have a tendency to migrate towardsfirst tool end 210. In one or more embodiments, the downhole PVT tool200 includes an intake mandrel 230 formed of an intake mandrel body 231.In one or more embodiments, intake mandrel 230 may be an isolationpacker with a first packer element 232 spaced apart from a second packerelement 234 along the intake mandrel body 231. Although not limited to aparticular type of packer, in one or more embodiments, intake mandrel230 can be a pad-based packer, a focused packer or an unfocused packer.In any event, intake mandrel 230 also includes at least one portmechanism 235 disposed along the intake mandrel body 231. Where intakemandrel 230 is a packer, port mechanism 235 may be positioned alongintake mandrel body 231 between the first and second packer elements 232and 234, respectively. In one or more embodiments, port mechanism 235may be an aperture formed along intake mandrel body 231, while in otherembodiments, port mechanism 235 may be a suction arm or probe 236 thatextends from intake mandrel body 231 to engage an adjacent wall ofwellbore 80 (see FIG. 1 ). Where port mechanism 235 is a suction arm236, suction arm 236 may include a pad 238 that bears against the wallof wellbore 80.

In one or more embodiments, the downhole PVT tool 200 includes a firstflowpath 215 formed within one or more tool segments 205-1 to 205-8,collectively referred to as “segments 205” and which segments 205include intake mandrel 230. As used herein, to the extent a “flowpath”is formed in a component of downhole PVT tool 200, it may also bereferred to as or otherwise considered a flowline. In any event, thefirst flowpath 215 extends from a first end 212 fluidically coupled tothe port mechanism 235 (the first end 212 begins at segment 205-5) to asecond end 217 (the second end 217 ends at segment 205-1). The downholePVT tool 200 may include at least one exit valve 218 disposed along thefirst flowpath 215, and in one or more embodiments, it has two or moreexit valves 218. Downhole PVT tool 200 also includes a first pump 240fluidically coupled to the first flowpath 215. In one or moreembodiments, first pump 240 is disposed along first flowpath 215 betweenexit valve 218 and the first end 212.

As illustrated in FIG. 2 , in one or more embodiments, a second flowpath225 is formed within one or more tool segments 205, with second flowpath225 extending from a first end 222 to a second end 227, the first end222 of the second flowpath 225 fluidically coupled to the port mechanism235. As illustrated, the first end 222 begins at segment 205-5, i.e.,intake mandrel 230. In the illustrated embodiment, the second end 227terminates at segment 205-8. Downhole PVT tool 200 includes a secondpump 250 fluidically coupled to the second flowpath 225. In one or moreembodiments, second pump 250 is disposed along second flowpath 225between the two ends 222 and 227.

While first and second flowpaths 215, 225 are shown spaced apart fromone another in different segments 205 of downhole PVT tool 200, in otherembodiments, first and second flowpaths 215, 225 may be formed in thesame segments 205 so long as the first and second flowpaths 215, 225remain separate from one another except as described herein adjacentintake mechanism 235.

As described above, when downhole PVT tool 200 is deployed, first toolend 210 will tend to be oriented above second tool end 220. For thisreason, in one or more embodiments, first flowpath 215 is spaced apartfrom second flowpath 225, and in particular, first flowpath 215 extendstowards first tool end 210 while second flowpath 215 extends towardssecond tool end 320. As such, phase behavior analysis can take advantageof the natural tendency of gas within the formation fluid to migratetowards the second end 217 of first flowpath 215, i.e., end 210 ofdownhole PVT tool 200 that is closest to the surface end 80 a ofwellbore 80.

Downhole PVT tool 200 may also include at least one primary sensorsystem 260 disposed along the first flowpath 215 between the first pump240 and the second end 217 of the first flowpath 215. Although notlimited to a particular type of sensor, in one or more embodiments,primary sensor system 260 may include any one or more of a pressuresensor, a temperature sensor, a density sensor or a densitometer, a flowrate sensor, composition sensor, an optical sensor, a capacitancesensor, a resistivity sensor, a sonic sensor, an ultrasonic sensor, achromatometer, and a microfluidic sensor, and the like.

In one or more embodiments, the downhole PVT tool 200 may furtherinclude at least one sample chamber disposed along one or both flowpaths215, 225. In the illustrated embodiment, multiple sample chambers 219are shown near the first tool end 210, while a second sample chamber 220is shown near the second tool end 220. In one or more embodiments, thedownhole PVT tool 200 also includes one or more temperature sensors 290disposed along one or both flowpaths 215, 225. Each flowpath 215, 225may further include valves 295 within one or more tool segments 205. Inone or more embodiments, the downhole PVT tool 200 may also include anoptical sensor 262, which, among other things, may be used to determinephase change or the concentration of contaminants in the formation fluidsample, although it will be understood that other sensors may be usedfor this purpose. In various embodiments, a fluid property analyzer iselectrically coupled to one of the sensors 260 or 262.

In one or more embodiments, at least a portion 215 a of first flowpath215 is defined within intake mandrel 230 and at least a portion 225 a ofsecond flowpath 225 is defined within intake mandrel 230 extending fromport mechanism 235. In some embodiments portion 215 a of first flowpath215 and portion 225 a of second flowpath 225 a may be separately formedwithin intake mandrel 230, while in other embodiments, portion 215 a offirst flowpath 215 and portion 225 a of second flowpath 225 mayintersect one another, while in yet other embodiments, portion 215 a offirst flowpath 215 and portion 225 a of second flowpath 225 may be thesame. Thus, in some embodiments, the initial flowpath from the portmechanism 235 may have a junction 237 at which point the first flowpath215 extends in a first direction (such as towards first tool end 210)and the second flowpath 225 extends in a second direction (such astowards second tool end 220). In any event, the junction 237 occursalong the flowpath between the port mechanism 235 and the pumps 240,250. In the illustrated embodiment, a portion 215 b, 225 b of theflowpaths 215, 225 converge or share a common path from port mechanism235 to junction 237, at which point flowpaths 215, 225 diverge.

Depending on their configuration asset forth above, at least oneflowpath 215, 225 begins at port mechanism 235. Where first and secondflowpaths 215, 225 do not intersect or converge or share a common pathwithin intake mandrel 230, intake mandrel 230 may include two portmechanisms 235 (see FIG. 3 ) where portion 215 a of first flowpath 215is fluidically coupled to one port mechanism 235 and portion 225 a ofsecond flowpath 225 is fluidically coupled to a separate port mechanism235. Where a port mechanism 235 includes a suction arm 236, then therelevant flowpath(s) extends through the suction arm 236. Where a portmechanism 235 includes a pad 238, then the relevant flowpath(s) beginsat the pad 238.

Referring to FIG. 3 , downhole PVT tool 110 is shown as downhole PVTtool 300, in accordance with one or more embodiments of the presentdisclosure. Downhole PVT tool 300 is operable to perform phase behaviormeasurements in-situ on formation fluids. Although downhole PVT tool 300is similar to the downhole PVT tool 200 and includes a first pump 340and a second pump 350, downhole PVT tool 300 further includes a pistonpump 380. In one or more embodiments, piston pump 380 can be configuredas a metered pump for fine pressure control during phase behavior tests,such as during, for example, depressurization.

As illustrated in FIG. 3 , in accordance with one or more embodiments,downhole PVT tool 300 has a first tool end 310, which can be referred toas the upper end, and a second tool end 320, which can be referred to asthe lower end. It will be appreciated that in one or more embodiments,downhole PVT tool 300 is generally positioned within a wellbore 80 sothat first tool end 310 extends towards the surface end 80 a of wellbore80, while second tool end 320 extends towards the terminal end 80 b ofwellbore 80 (see FIG. 1 ). Moreover, whether wellbore 80 issubstantially vertical or deviated, in one or more embodiments, firsttool end 310 is generally positioned above, or otherwise has a higherelevation than, second tool end 320 such that gas entrained withinformation fluid captured within downhole PVT tool 300 will have atendency to migrate towards first tool end 310. In one or moreembodiments, the downhole PVT tool 300 includes an intake mandrel 330formed of an intake mandrel body 331. In one or more embodiments, intakemandrel 330 may be an isolation packer with a first packer element 332spaced apart from a second packer element 334 along the intake mandrelbody 331 Although intake mandrel 330 is shown as a packer, it need notbe, and persons of skill in the art will appreciate that intake mandrel330 may be any tool component that can be utilized to establish fluidcommunication with the wellbore annulus or the formation. In any event,intake mandrel 330 includes a port mechanism 335 disposed along intakemandrel body 331. Where intake mandrel 330 is a packer, port mechanism335 may be positioned along intake mandrel body 331 between the firstand second packer elements 332 and 334, respectively. In the illustratedembodiment, a first port mechanism 335 a and a separate second portmechanism 335 b are illustrated, although first and second portmechanism 335 a, 335 b could be combined into a single port mechanism335 such as is described with respect to FIG. 2 .

In one or more embodiments, the downhole PVT tool 300 includes a firstflowpath 315 formed within one or more tool segments 305-1 to 305-9,collectively referred to as “segments 305” and which segments 305include intake mandrel 230. Although illustrated as discreet componentsthat make up downhole PVT tool 300, in one or more embodiments, toolsegments 305 may be integrally formed into a single piece downhole PVTtool. The first flowpath 315 extends from a first end 312 fluidicallycoupled to the port mechanism 335 a (the first end 312 begins at segment305-5) to a second end 317 (the second end 317 ends at segment 305-1).The downhole PVT tool 300 may include at least one exit valve 318disposed along the first flowpath 315, and in one or more embodiments,it has at least two exit valves 318. Exit valves 318 may be in fluidcommunication with the exterior of downhole PVT tool 300 or with othercomponents of the downhole PVT tool 300, such as expansion chambers orthe like. Downhole PVT tool 300 also includes a first pump 340fluidically coupled to the first flowpath 315. In one more embodiments,first pump 340 is disposed along first flowpath 315 between exit valve318 and the first end 312. In one or more embodiments, first pump 340 isa variable rate pump to allow the flow rate of formation fluid movingalong first flowpath 315 to be varied during investigation of the phaseresponse. Furthermore, first pump 340 is a reversible pump, allowing thedirection of flow along first flowpath 315 to be reversed as describedherein.

As illustrated in FIG. 3 , in one or more embodiments, a second flowpath325 is formed within one or more tool segments 305, with the secondflowpath 325 extending from a first end 322 fluidically coupled to theport mechanism 335 b to a second end 327. As illustrated, the first end322 begins at segment 305-5, i.e. intake mandrel 330. In the illustratedembodiment, the second end 327 terminates at segment 305-8. Thus, thefirst flowpath 315 generally extends from intake mandrel 330 towards theupper end 310 of downhole PVT tool 300 and the second flowpath 325generally extends in a direction opposite from the first flowpath 315,namely towards the lower end 320 of downhole PVT tool 300. Downhole PVTtool 300 includes a second pump 350 fluidically coupled to the secondflowpath 325. In one or more embodiments, second pump 350 is disposedalong second flowpath 325 between the two ends 322 and 327. Second pump350 may be a reversible pump, such as first pump 340, or a singledirection pump. Likewise, second pump 350 may be a variable rate pump ora constant speed pump since it will be appreciated that unlike firstpump 340 and first flowpath 315, second pump 350 and second flowpath 325are not being utilized to investigate phase characteristics of theformation fluid as occurs with respect to first flowpath 325.

Downhole PVT tool 300 may also include at least one primary sensorsystem 360 disposed along the first flowpath 315 between the first pump340 and the second end 317 of the first flowpath 315. In one or moreembodiments, primary sensor system 360 includes at least a pressuresensor. Although not limited to any further particular type of sensor,primary sensor system 360 may further include one or more of atemperature sensor, a density sensor or a densitometer, a flow ratesensor, composition sensor, an optical sensor, a capacitance sensor, aresistivity sensor, a sonic sensor, an ultrasonic sensor, achromatometer, and a microfluidic sensor, and the like.

Downhole PVT tool 300 may further include sample chambers 319 and 320disposed along one or both flow paths 315, 325. In the illustratedembodiment, multiple sample chambers 319 are disposed near the firsttool end 310 while a sample chamber 320 is disposed near the second toolend 320. In one or more embodiments, the downhole PVT tool 300 may alsoinclude one or more additional sensors 390, such as temperature sensorsand/or pressure sensors, within one or more tool segments 305. Further,the downhole PVT tool 300 may include an optical sensor 360 disposedalong first flowpath 315. In various embodiments, a fluid propertyanalyzer is electrically coupled to one of the sensors 360 or 362.

As illustrated in FIGS. 2 and 3 , the downhole PVT tools 200 and 300each have two separate pumps, where each pump is disposed to moveformation fluid along different flowpaths, and which flowpaths, in oneor more embodiments, may extend in opposite directions along the axiallength of the downhole PVT tool. By splitting formation fluid flow alongseparate flowpaths, the flow direction between two points along oneflowpath can be reversed while fluid flow along the other flowpath maycontinue uninterrupted. In this regard, the pump rates along theseparate flowpaths may be different. For example, flow along a firstflowpath may be varied in order to investigate phase response of theformation fluid to changes in physical conditions. In this regard, thefirst pump may be used to pressurize or “pump up” the formation fluidsample pressure from a first pressure to a second pressure that ishigher than the first pressure, and thereafter, the first pump may bereversed to depressurize, bleed off or otherwise “pump out” theformation fluid sample. In one or more embodiments, a pump rate can bevaried more than ten or more times between an open section of aflowpath, i.e., the second flowpath, and a closed section of a flowpath,i.e., the first flowpath, in order to substantially continue the pumpout during fluid phase measurements. Using at least one fluidmeasurement sensor and preferably two or more fluid measurement sensors,fluid properties along the first flowpath may be monitored during pumpup and also during pump out. In one or more embodiments, fluidproperties to be measured include, but not limited to density,viscosity, temperature, pressure, capacitance, compressibility,sonic/ultrasonic sensors including speed of sound measurements,composition including but not limited to that measured by opticalmeasurements or microfluidic measurements, or chromatographicmeasurements, as described with respect to FIGS. 2 and 3 .

In one or more embodiments, liquid height measurements may also beperformed during the pump out of the first flowpath with either multiplefluid sensing measurements from different sensors along one of theflowpaths (in any of the first and second flowpaths 215, 225, 315, or325) or with distributed sensing measurements along any of the first andsecond flowpaths 215, 225, 315, or 325. Alternatively, sonic/ultrasonicmeasurements may be made along any of the flowpaths 215, 225, 315, or325 to determine liquid height. Such a measurement is most easily madein a single tool section, e.g., any of segments 205 and 305, but may bemade in multiple sections. In one or more embodiments, phase changessuch as bubble point or asphaltene precipitation point may be directlymeasured as the point of inflection for any of the fluid measurementsensors, however, optical sensors, such as sensor 260 or 360, areparticularly sensitive to these phase changes. Density sensors are alsosensitive to bubble point phase changes however less so for asphalteneprecipitation phase changes. Using multiple sensors or magnitudereadings of the sensors, phase change types may be derived.Compositional changes as a function of pressure may also be measuredwith compositional sensors for specific fluid phases in which thosesensors, e.g., sensors 260, 270, 360, or 370, are in contact. The fluidis also phase separated such that gas phase measurements may beperformed, in accordance with one or more embodiments disclosed herein.In other embodiments, measurements may be taken along the first flowpathduring pressurization and then during controlled depressurization inorder to better characterize the phase behavior of the formation fluid,all while simultaneously continuing to pump formation fluid along thesecond flowpath.

Based on the downhole PVT tools 200 and 300 described herein, or anyvariation in the configuration based on the downhole PVT tools 200 and300, PVT fluid measurements and characterization of phase behavior of aformation fluid can be performed without a bypass flowpath. As discussedabove, the use of multiple individual pumps and flowpaths tied into asingle probe/packer along separate flowpaths can allow reversal of atleast one of those pumps to measure phase behavior without suspending orinterfering with formation fluid flow along a separate flowpath.

Referring to FIG. 4 , a downhole method 400 for performing in-situ phasebehavior characterization of formation fluid is illustrated. In a firststep 410, the method includes obtaining formation fluid from a samplinglocation along a wellbore. In some embodiments, the wellbore may be at adepth of 100 meters or more, while in other embodiments, the wellboremay be at a depth of 1000 meters or more, while in other embodiments,the wellbore may be at a depth of 2000 meters or more. In each case, itwill be appreciated that the formation fluid pressure at the depth ofthe wellbore is significantly greater than sea level atmosphericpressure. Conducting in-situ phase behavior analysis of the isolatedformation fluid sample permits more accurate understanding of phaseresponse to actual conditions at the sampling location than would be thecase for samples retrieved and analyzed at the surface. In any event, inone or more embodiments, the formation fluid may be obtained by drawingformation fluid from the formation. As described above, a probe or padmay be utilized to engage a wellbore wall at a sampling location withinthe formation, and a pump may be activated to create a negative pressureat the junction of the pad or probe with the wellbore wall, therebycausing the formation fluid to be drawn from the formation and into adownhole PVT tool as described herein. In this regard, a downhole PVTtool may be positioned in the wellbore adjacent a zone of interest information. Thereafter, a probe or pad may be extended from the downholePVT tool to engage the wellbore wall and form a suction coupling withthe wellbore wall. In other embodiments, the formation fluid may bedrawn from the annulus surrounding the downhole PVT tool. In such cases,an isolation packer may be activated to isolate a sampling locationalong the annulus, and the fluid may be drawn from the annulus at theisolated sampling location.

As the formation fluid is drawn into or otherwise obtained by thedownhole PVT tool, in step 420, a first portion of the formation fluidis pumped along a first flowpath, i.e., the first flowpath 215 or 315.Relatedly, at step 430, a second portion of the formation fluid ispumped along a second flowpath, i.e., the second flowpath 225 or 325. Inone embodiment, the formation fluid may initially be pumped along asingle flowpath, such as when it is drawn in to the tool, andthereafter, the single flowpath may diverge into a first flowpath and asecond flowpath, such that formation fluid passing along the firstflowpath represents the first portion of the formation fluid andformation fluid passing along the second flowpath represents the secondportion of the formation fluid. In this regard, a first pump is used topump the first portion along the first flowpath and a second pump isused to pump the second portion along the second flowpath. Where theflowpaths initially are converged, the second pump may be utilized toinitiate formation fluid flow by generating a negative pressure in thesingle flowpath to draw the formation fluid into the downhole PVT tooland along the second flowpath as the second portion of the formationfluid. After formation fluid flow is initiated, the first pump may beutilized to draw the first portion from the initiated formation fluidflow. In such case, both pumps may be operated simultaneously.

In other embodiments, the first pump is utilized to draw formation fluidfrom the formation (or annulus, as the case may be) directly into thefirst flowpath and the second pump is utilized to draw formation fluidfrom the formation (or annulus, as the case may be) directly into thesecond flowpath, such that the first portion of the formation fluid andthe second portion of the formation fluid are never comingled. Again,both pumps may be operated simultaneously.

Regardless, as to whether the flowpaths are separate or comingled, thetwo separate pumps permit simultaneous pumping of the first portion ofthe formation fluid along a first flowpath and pumping the secondportion of the formation fluid along a second flowpath separate from thefirst flowpath. In one or more embodiments, the first portion of theformation fluid is pumped at a first flowrate and the second portion ofthe formation fluid is pumped at a second flowrate different than thefirst flowrate. In some embodiments, the flow rates produced by the twoindividual pumps can vary more than ten times between the two pumps.

In one or more embodiments where the first and second flowpaths extendin substantially opposite axial directions in the downhole PVT tool, thefirst portion of the formation fluid is pumped from a sampling location,i.e., the formation fluid intake location, in a first axial directionsuch as upstream towards the surface end of the wellbore, and the secondportion of the formation fluid is pumped from the sampling location in asecond axial direction second axial direction such as downstream towardsthe terminal end of the wellbore. Thus, for each flowpath, the formationfluid is initially pumped from a first end of the flowpath towards asecond end of the flowpath. In the case of the first flowpath, a valvemay be open at the end of the first flowpath to allow the formationfluid to exit the first flowpath through the valve prior to isolating aformation fluid sample as described below.

At step 440, the first portion of the formation fluid is isolated withinthe first flowpath while the second portion of the formation fluid alongthe second flowpath continues to be pumped. This step of the operationis possible because of the use of two individual pumps 240 and 250. Inone or more embodiments, the valve described above may be closed so thatthe first flowpath forms a chamber as pump 240 is operated to fill thechamber.

At step 450, the method 400 includes changing a physical condition ofthe isolated first portion of the formation fluid. In one or moreembodiments, this change may be implemented over a discrete timeinterval from a time (t1) to a time (t2). In one or more embodiments,the physical condition being changed can be any of pressure, volume,temperature, viscosity, etc. Regardless of the physical condition, thechange may be to increase or decrease the physical condition. Forexample, the change may be to increase or decrease pressure, volume ortemperature. In one or more embodiments, changing the physical conditionincludes changing the fluid pressure of the first fluid portion. In oneor more embodiments, changing the fluid pressure is accomplished byaltering the volume of the first flowpath. In some embodiments, changingthe fluid pressure is accomplished with the first pump by continuing tooperate the pump to increase pressure on the first portion of theformation fluid, while in other embodiments, changing the fluid pressureis accomplished with the first pump by reversing the direction of thepump and fluid flow and operating the pump to decrease pressure on thefirst portion of the formation fluid. In one or more embodiments,changing the physical condition includes increasing the pressure on thefirst fluid portion over the time interval. In one or more embodiments,changing the physical condition includes decreasing the pressure on thefirst fluid portion over the time interval. This may be accomplished bypumping the first portion of the formation fluid along the firstflowpath in a second direction opposite the first direction, and inparticular pumping the first portion along the first flowpath from thesecond end of the first flowpath towards the first end of the firstflowpath. Although not limited to a particular time interval, in someembodiments, the time interval can be from about 1 second to about 10minutes, from about 10 second to about 1 minutes, from about 1 second toabout 1 hour, from about 1 minute to about 24 hours, inclusive of anyranges of time interval between 1 second and 24 hours. Regardless of thetime interval, in one or more embodiments, particularly where theformation fluid sample in the first flowpath is drawn from formationfluid flowing along the second flowpath, it is desirable to allowflow-through along the second flowpath for a period of time to minimizethe presence of contaminants in the formation fluid sample, seeking ascontaminant-free sample as possible.

In step 460, at least one fluid property of the first portion of theformation fluid is measured. In one or more embodiments, the fluidproperty may be measured before and after a physical property of thefirst portion of the formation fluid is changed in step 450. Thus, afluid property measurement may be taken at the first time (t1) and atthe second time (t2) to obtain at least two measurements of the fluidproperty. In other embodiments, the fluid property may be measured as afunction of time as the physical condition is changed over the timeinterval from time (t1) to time (t2). The at least one fluid propertymeasured may include any of pressure, temperature, density, flow rate,composition, optical property, capacitance, resistivity, sonic property,ultrasonic property, chromatographic, and microfluidic, and the like.

Finally, at step 470, the phase behavior of the formation fluid ischaracterized based on the at least two measurements. In this regard, aphase behavior property may be identified. For example, a phase changepressure point can be identified as pressure is removed from theformation fluid. The phase behavior property of the formation fluid caninclude any property including, but not limited to fluid fraction,compressibility, viscosity, and gas-oil-ratio (GOR) measurements.

In one or more embodiments of the method 400, pumping the first portionof the formation fluid along the first flowpath includes pumping thefirst portion along the flowpath in a first direction, e.g., towardssegment 205-1 in FIG. 2 (or segment 305-1 in FIG. 3 ), and then pumpingthe first portion of the formation fluid along the flowpath in a seconddirection, e.g., towards segment 205-8 in FIG. 2 (or segment 305-8 inFIG. 3 ). In one or more embodiments of the method 400, pumping in thefirst direction includes pumping the first portion along the firstflowpath from a first end of the flowpath towards a second end of theflowpath, i.e., from segment 205-5 to segment 205-1 in FIG. 2 (or fromsegment 305-5 to segment 305-1 in FIG. 3 ). Likewise, pumping in thesecond direction includes pumping the first portion along the firstflowpath from the second end of the first flowpath towards the first endof the first flowpath, i.e., from segment 205-1 to segment 205-5 in FIG.2 (or from segment 305-1 to segment 305-5 in FIG. 3 ).

In one or more embodiments of the method 400, pumping the first portionof the formation fluid along the first flowpath includes pumping thefirst portion along the first fluid path towards an open first flowpathvalve, e.g., exit valve 218 or 318, disposed along the first flowpath.In such instances, the method 400 further includes closing the firstflowpath valve to isolate the first portion, continuing to pump thefirst portion until a predetermined pressure on the first portion isreached, bleeding down the pressure on the first portion, and then,measuring the fluid property as the pressure on the first portion isbled down. In one or more embodiments, bleeding down can include pumpingthe first portion from the first flowpath.

In one or more embodiments, pumping the first portion from the firstflowpath includes pumping the first portion into the wellbore annulusaround the downhole PVT tool. In other embodiments, pumping the firstportion from the first flowpath includes pumping the first portion tothe second flowpath. In some embodiments of the method 400, isolatingmeans closing a valve along the first flowpath. In some embodiments,changing the physical condition of the isolated first portion includescontinuing to pump the first portion until a predetermined pressure onthe first portion is reached, bleeding down the pressure on the firstportion, and measuring the fluid property as the pressure on the firstportion is bled down. In such instances, bleeding down may includepumping the first portion from the first flowpath.

In one or more embodiments of the method 400, pumping the first portionand second portion of the formation fluid can include pumping the firstportion at a first flowrate and pumping the second portion at a secondflowrate different than the first flowrate. In some instances, the firstflowrate is higher than the second flowrate. In other instances, thereverse is true. In still yet one or more other embodiments, the secondflowrate for pumping the second portion compensates the rate addition ofthe first flowpath due to the reversal.

While in some embodiments it is desirable to minimize contaminants inthe formation fluid sample isolated in the first flowpath, it may bedesirable to obtain formation fluid sample data with a variety ofsamples having different contaminant levels or concentrations, such as ameasured amount of mud filtrated per liter of sample. Using contaminatedsamples with different levels or concentrations of contamination, PVTproperties for a hypothetical “contaminant-free” formation fluid samplecan be estimated. These PVT properties for the hypothetical“contaminant-free” formation fluid sample can then be utilized toestimate phase behavior of the formation fluid. In yet otherembodiments, PVT properties may be measured as a function ofcontamination concentration of the formation fluid to consider howvarious properties of the formation fluid are impacted by contamination.Thus, a contaminant concentration and a PVT property of a firstformation fluid sample may be measured and compared to a contaminantconcentration and the PVT property of a second formation fluid samplewith a different concertation. This can permit the estimation of theimpact of the concentration on the measured PVT property. Similarly, acontaminant concentration and a physical property of a first formationfluid sample may be measured and compared to a contaminant concentrationand the physical property of a second formation fluid sample with adifferent concertation. This can permit the estimation of the impact ofthe contaminant concentration on the measured physical property. Inother embodiments, a contaminant concentration and a phase behaviorproperty of a first formation fluid sample may be measured and comparedto a contaminant concentration and the phase behavior of a secondformation fluid sample with a different concertation. This can permitthe estimation of the impact of the contaminant concentration on themeasured phase behavior property.

In one or more embodiments, the fluid property that can be measuredincludes one of pressure, temperature, density, flow rate, composition,optical property, capacitance, resistivity, sonic property, ultrasonicproperty, chromatographic, and microfluidic. In other embodiments, thetwo measurements can be a pressure measurement. In one or moreembodiments, these measurements can be performed at multiple locationsalong the first flowpath through a distributed measurement system. Inone or more embodiments, changing the internal volume of the fluidinduces a phase change in the fluid, and a height of free gas above thefluid can be measured after the phase change. In one or moreembodiments, at least one phase behavior property that can be determinedincludes fluid fraction, compressibility, viscosity, and gas-oil-ratio(GOR) measurement.

Thus, a downhole PVT tool for performing in-situ phase behaviormeasurements in a wellbore has been described. The downhole PVT mayinclude an intake mandrel having an intake mandrel body with a portmechanism disposed along the intake mandrel body; a first flowpathformed within one or more tool segments, the first flowpath having afirst end and a second end, with the first end of the first flowpathfluidically coupled to the port mechanism; at least one exit valvedisposed along the first flowpath; a first pump fluidically coupled tothe first flowpath; a second flowpath formed within one or more toolsegments, the second flowpath having a first end and a second end, withthe first end of the second flowpath fluidically coupled to the portmechanism; a second pump fluidically coupled to the second flowpath; andat least one primary sensor system disposed along the first flowpathbetween the second pump and the second end of the first flowpath.

For any of the foregoing embodiments, the downhole PVT tool may includeany one of the following elements, alone or in combination with eachother:

-   -   The downhole PVT tool has a first tool end and a second tool        end.    -   The downhole PVT tool has an isolation packer having a first        packer element spaced apart from a second packer element along a        packer body with a port disposed along the packer body between        the first and second packer elements.    -   The downhole PVT tool has a first flowpath formed within one or        more tool segments.    -   The first flowpath has a first end and a second end, with the        first end of the first flowpath fluidically coupled to the port.    -   Each tool segment has an exterior surface.    -   The downhole PVT tool has at least one exit valve disposed along        the first flowpath.    -   The downhole PVT tool has a first pump fluidically coupled to        the first flowpath between the exit valve and the first end of        the first flowpath.    -   The downhole PVT tool has a second flowpath formed within one or        more tool segments.    -   The second flowpath has a first end and a second end, with the        first end of the second flowpath fluidically coupled to the        port.    -   The downhole PVT tool has a second pump fluidically coupled to        the second flowpath between the two ends of the second flowpath.    -   The downhole PVT tool has at least one primary sensor system        disposed along the first flowpath between the second pump and        the second end of the first flowpath.    -   The downhole PVT tool has at least one secondary sensor system        disposed along the second flowpath.    -   The first pump is a reversible pump.    -   At least one of the pumps is a variable speed pump.    -   The first flowpath extends from the isolation packer towards the        first tool end.    -   The second flowpath extends from the isolation packer towards        the second tool end.    -   At least one primary sensor system includes a sensor selected        from the group consisting of a pressure sensor, a temperature        sensor, a density sensor, a flow rate sensor, composition        sensor, an optical sensor, a capacitance sensor, a resistivity        sensor, a sonic sensor, an ultrasonic sensor, a chromatometer,        and microfluidic sensor.    -   The downhole PVT tool has a fluid property analyzer electrically        coupled to the at least one primary sensor.

Relatedly, a method for performing downhole, in-situ phase behaviormeasurements of formation fluid collected in a wellbore has beendescribed. Embodiments of the method may include drawing formation fluidfrom the wellbore; pumping a first portion of the formation fluid alonga first flowpath; pumping a second portion of the formation fluid alonga second flowpath; isolating the first portion of the formation fluidwhile continuing pump the second portion of the formation fluid alongthe second flowpath; changing a physical condition of the isolated firstportion over a time interval; measuring at least one fluid property ofthe first portion while changing the physical condition; obtaining atleast two measurements of the fluid property over the time interval; anddetermining at least one phase behavior property of the formation fluidfrom the at least two measurements. In other embodiments, the method mayinclude performing downhole phase behavior measurements may includedrawing a fluid from a formation through a probe, the probe attached toa first flowpath and a second flowpath; pumping the fluid to the firstflowpath via a first pump, the first flowpath having at least one exitvalve fluidically connected to the first flowpath; closing the at leastone exit valve of the first flowpath, thereby isolating the fluidlocated in the first flowpath from the wellbore; changing an internalvolume of the fluid attached to the first flowpath by actuating thefirst pump; measuring at least one fluid property at least two differentinternal volume levels; and determining at least one phase behaviorproperty from the at least one measured fluid property. In yet otherembodiments, the method may include obtaining formation fluid from asampling location in the wellbore; pumping a first portion of theformation fluid along a first flowpath; pumping a second portion of theformation fluid along a second flowpath; isolating the first portion ofthe formation fluid along the first flowpath while continuing to pumpformation fluid along the second flowpath; changing a physical conditionof the isolated first portion over a time interval while continuing topump formation fluid along the second flowpath; measuring at least onefluid property of the first portion while changing the physicalcondition to obtain at least two measurements of the fluid property overthe time interval; and determining at least one phase behavior propertyof the formation fluid from the at least two measurements. In still yetother embodiments, the method may include engaging the formation with aprobe at a sampling location within a wellbore; drawing formation fluidfrom the formation through the probe; pumping the formation fluid fromthe probe to a first flowpath via a first pump; isolating the formationfluid located in the first flowpath; increasing pressure on the isolatedformation fluid utilizing the first pump and then decreasing thepressure on the isolated formation fluid; simultaneously as the pressureon the isolated formation fluid is increased utilizing the first pump,utilizing a second pump to pump formation fluid from the probe along asecond flowpath; measuring at least one fluid property of the formationfluid of the first flowpath over a time interval as the pressure on theformation fluid in the first flowpath is decreased; and determining atleast one phase behavior property from the at least one measured fluidproperty.

For the foregoing embodiments, the method may include any one of thefollowing steps, alone or in combination with each other:

-   -   Changing the physical condition includes changing pressure on        the first fluid portion.    -   Obtaining formation fluid from a formation at a sampling        location comprises drawing formation fluid from the formation.    -   Obtaining formation fluid from a formation at a sampling        location comprises engaging a wellbore wall with a pad and        creating a negative pressure at the surface of the pad to draw        formation fluid into a flowpath.    -   Obtaining formation fluid from a formation at a sampling        location comprises drawing formation fluid from the annulus        around a downhole PVT tool.    -   Pumping a first portion of the formation fluid along a first        flowpath comprises pumping the first portion from the sampling        location upstream towards surface; and pumping a second portion        of the formation fluid along a second flowpath comprises pumping        the second portion from the sampling location downstream towards        the wellbore end.    -   Pumping a first portion of the formation fluid along a first        flowpath comprises pumping the first portion from the sampling        location upstream towards surface.    -   Pumping a second portion of the formation fluid along a second        flowpath comprises pumping the second portion from the sampling        location downstream towards the wellbore end.    -   Changing the pressure includes altering the volume of the first        flowpath.    -   Changing the physical condition includes increasing the pressure        on the first fluid portion over the time interval, and measuring        the fluid property at a first time and a second time.    -   Changing the physical condition includes decreasing the pressure        on the first fluid portion over the time interval, and measuring        the fluid property at a first time and a second time.    -   Pumping a first portion of the formation fluid along a first        flowpath and simultaneously pumping a second portion of the        formation fluid along a second flowpath.    -   Pumping the second portion of the formation fluid along the        second flowpath is simultaneous with pumping the first portion        of the formation fluid along the first flowpath.    -   Utilizing a first pump to pump a first portion of the formation        fluid along the first flowpath; and utilizing a second pump to        pump a second portion of the formation fluid along the second        flowpath.    -   Pumping the first portion of the formation fluid along the first        flowpath includes pumping the first portion along the flowpath        in a first direction; and then pumping the first portion of the        formation fluid along the flowpath in a second direction.    -   Pumping in the first direction includes pumping the first        portion along the first flowpath from a first end of the        flowpath towards a second end of the flowpath.    -   Pumping in the second direction includes pumping the first        portion along the first flowpath from the second end of the        flowpath towards the first end of the flowpath.    -   Pumping the first portion of the formation fluid along the first        flowpath includes pumping the first portion along the first        fluid path towards an open first flowpath valve disposed along        the first flowpath.    -   Measuring contaminant concentration and a PVT property of a        first formation fluid sample; measuring a contaminant        concentration and the PVT property of a second formation fluid        sample with a different concertation; and estimating the impact        of the contaminant concentration on the measured PVT property.    -   The measured PVT property is temperature.    -   The measured PVT property is pressure.    -   Measuring contaminant concentration and a physical property of a        first formation fluid sample; measuring a contaminant        concentration and the physical property of a second formation        fluid sample with a different concertation; and estimating the        impact of the contaminant concentration on the measured physical        property.    -   Measuring contaminant concentration and a phase behavior        property of a first formation fluid sample; measuring a        contaminant concentration and the phase behavior property of a        second formation fluid sample with a different concertation; and        estimating the impact of the contaminant concentration on the        measured phase behavior property.    -   The method may include closing the first flowpath valve to        isolate the first portion.    -   The method may include continuing to pump the first portion        until a predetermined pressure on the first portion is reached.    -   The method may include bleeding down the pressure on the first        portion.    -   The method may include measuring the fluid property as the        pressure on the first portion is bled down.    -   Bleeding down includes pumping the first portion from the first        flowpath.    -   Pumping the first portion from the first flowpath includes        pumping the first portion back into the wellbore.    -   Pumping the first portion from the first flowpath includes        pumping the first portion to the second flowpath.    -   Isolating includes closing a valve along the first flowpath.    -   Changing the physical condition of the isolated first portion        includes continuing to pump the first portion until a        predetermined pressure on the first portion is reached; bleeding        down the pressure on the first portion; and measuring the fluid        property as the pressure on the first portion is bled down.    -   Bleeding down includes pumping the first portion from the first        flowpath.    -   Pumping the first portion and second portion of the formation        fluid includes pumping the first portion at a first flowrate and        pumping the second portion at a second flowrate different than        the first flowrate.    -   The first flowrate is higher than the second flowrate.    -   The second flowrate for pumping the second portion compensates        the rate addition of the first flowpath due to the reversal.    -   At least one fluid property measured includes one of pressure,        temperature, density, flow rate, composition, optical property,        capacitance, resistivity, sonic property, ultrasonic property,        chromatographic, and microfluidic.    -   One of the at least two measurements is a measurement of        pressure.    -   At least one fluid property measured occurs at multiple        locations along the first flowpath through a distributed        measurement system.    -   Changing the internal volume induces a phase change in the        fluid, and a height of free gas above the fluid is measured        after the phase change.    -   At least one phase behavior property determined is one of fluid        fraction, compressibility, viscosity, and gas-oil-ratio (GOR)        measurement.

While various embodiments have been illustrated in detail, thedisclosure is not limited to the embodiments shown. Modifications andadaptations of the above embodiments may occur to those skilled in theart. Such modifications and adaptations are in the spirit and scope ofthe disclosure.

What is claimed is:
 1. A method for performing downhole in-situ phasebehavior measurements of formation fluid collected in a wellboreextending from a surface end to a terminal end, the method comprising:obtaining formation fluid from a sampling location in the wellbore;pumping a first portion of the formation fluid along a first flowpath,further comprising pumping the first portion from the sampling locationupstream towards the surface end; pumping a second portion of theformation fluid along a second flowpath, further comprising pumping thesecond portion from the sampling location downstream towards theterminal end; isolating the first portion of the formation fluid alongthe first flowpath while continuing to pump formation fluid along thesecond flowpath; changing a physical condition of the isolated firstportion over a time interval while continuing to pump formation fluidalong the second flowpath; measuring at least one fluid property of thefirst portion while changing the physical condition to obtain at leasttwo measurements of the fluid property over the time interval; anddetermining at least one phase behavior property of the formation fluidfrom the at least two measurements.
 2. The method of claim 1, whereinchanging the physical condition comprises changing pressure on the firstfluid portion.
 3. The method of claim 1, wherein changing the physicalcondition comprises increasing the pressure on the first fluid portionover the time interval, and measuring the fluid property at a first timeand a second time.
 4. The method of claim 1, wherein changing thephysical condition comprises decreasing the pressure on the first fluidportion over the time interval, and measuring the fluid property at afirst time and a second time.
 5. The method of claim 1, wherein pumpingthe first portion of the formation fluid along the first flowpathcomprises pumping the first portion along the flowpath in a firstdirection; and then pumping the first portion of the formation fluidalong the flowpath in a second direction.
 6. The method of claim 5,wherein pumping in the first direction comprises pumping the firstportion along the first flowpath from a first end of the flowpathtowards a second end of the flowpath; and wherein pumping in the seconddirection comprises pumping the first portion along the first flowpathfrom the second end of the flowpath towards the first end of theflowpath.
 7. The method of claim 1, wherein pumping the first portion ofthe formation fluid along the first flowpath comprises pumping the firstportion along the first fluid path towards an open first flowpath valvedisposed along the first flowpath; the method further comprising:closing the first flowpath valve to isolate the first portion;continuing to pump the first portion until a predetermined pressure onthe first portion is reached; bleeding down the pressure on the firstportion; and measuring the fluid property as the pressure on the firstportion is bled down.
 8. The method of claim 7, wherein bleeding downcomprises pumping the first portion from the first flowpath.
 9. Themethod of claim 7, wherein pumping the first portion from the firstflowpath comprises pumping the first portion into an annulus within thewellbore.
 10. The method of claim 1, wherein changing the physicalcondition of the isolated first portion comprises continuing to pump thefirst portion until a predetermined pressure on the first portion isreached; bleeding down the pressure on the first portion; and measuringthe fluid property as the pressure on the first portion is bled down.11. The method of claim 1, wherein determining at least one phasebehavior property comprises measuring contaminant concentration and aphysical property of a first formation fluid sample; measuring acontaminant concentration and the physical property of a secondformation fluid sample with a different concertation; and estimating theimpact of the contaminant concentration on the measured physicalproperty.
 12. A downhole PVT tool for performing phase behaviormeasurements in a wellbore, the downhole PVT tool having a first toolend and a second tool end, comprising: an intake mandrel having anintake mandrel body with a port mechanism disposed along the intakemandrel body; a first flowpath formed within one or more tool segments,wherein the first flowpath extends from the intake mandrel towards thefirst tool end, the first flowpath having a first end and a second end,with the first end of the first flowpath fluidically coupled to the portmechanism; at least one exit valve disposed along the first flowpath; afirst pump fluidically coupled to the first flowpath; a second flowpathformed within one or more tool segments, wherein the second flowpathextends from the intake mandrel towards the second tool end, the secondflowpath having a first end and a second end, with the first end of thesecond flowpath fluidically coupled to the port mechanism; a second pumpfluidically coupled to the second flowpath; and at least one primarysensor system disposed along the first flowpath between the second pumpand the second end of the first flowpath.
 13. The system of claim 12,further comprising: at least one secondary sensor system disposed alongthe second flowpath.
 14. The system of claim 12, wherein the first pumpis a reversible pump, and wherein the port mechanism is an arm with asuction pad attached thereto, at least one of the flowpaths extendingthrough the arm to the suction pad.
 15. The system of claim 12, whereinthe at least one primary sensor system comprises at least one sensorselected from the group consisting of a pressure sensor, a temperaturesensor, a density sensor, a flow rate sensor, composition sensor, anoptical sensor, a capacitance sensor, a resistivity sensor, a sonicsensor, an ultrasonic sensor, a chromatometer, microfluidic sensor, andcombinations thereof.
 16. A method for performing downhole in-situ phasebehavior measurements of formation fluid collected in a wellboreextending from a surface end to a terminal end, the method comprising:engaging the formation with a probe at a sampling location within awellbore; drawing formation fluid from the formation through the probe;pumping the formation fluid from the probe to a first flowpath via afirst pump, wherein the first flowpath is directed upstream towards thesurface end; isolating the formation fluid located in the firstflowpath; increasing pressure on the isolated formation fluid utilizingthe first pump and then decreasing the pressure on the isolatedformation fluid; simultaneously as the pressure on the isolatedformation fluid is increased utilizing the first pump, utilizing asecond pump to pump formation fluid from the probe along a secondflowpath, wherein the second flowpath is directed downstream towards theterminal end; measuring at least one fluid property of the formationfluid of the first flowpath over a time interval as the pressure on theformation fluid in the first flowpath is decreased; and determining atleast one phase behavior property from the at least one measured fluidproperty.
 17. The method of claim 16, wherein the at least one fluidproperty measured comprises at least one measurement selected from thegroup consisting of pressure, temperature, density, flow rate,composition, optical property, capacitance, resistivity, sonic property,ultrasonic property, chromatographic, microfluidic measurements, andcombinations thereof.
 18. The method of claim 16, wherein the at leastone phase behavior property determined comprises at least one phasebehavior property selected from the group consisting of fluid fraction,compressibility, viscosity, gas-oil-ratio (GOR) measurement, andcombinations thereof.
 19. The method of claim 16 further comprisingmeasuring at least one fluid property of the formation fluid of thefirst flowpath over a time interval as the pressure on the formationfluid in the first flowpath is increased.
 20. The method of claim 16,wherein increasing the pressure on the isolated formation fluid anddecreasing the pressure on the isolated formation fluid furthercomprises continuing to pump the isolated formation fluid until apredetermined pressure is reached; bleeding down the pressure on theisolated formation fluid; and measuring the at least one fluid propertyof the isolated formation fluid as the pressure is bled down.